The invention finds application in the treatment of the production streams of heavy oil reservoirs, particularly where thermal recovery techniques are utilized.
Exemplary thermal recovery techniques include steam injection, in-situ combustion and cyclic steam injection ("huff and puff"). Such techniques focus on reducing the viscosity of the immobile oil in place, so that it can be driven to a production well and recovered.
Typically, the composition of the production stream from a thermal recovery process can vary, from a stream comprising oil, water, gases and solids in an emulsified state to a relatively clean but viscous oil. The composition, and also the viscosity of the produced stream, thus can vary widely and depend to some extent on the type or stage of production. For example, when employing a `huff and puff` operation, in the initial stages of the production cycle, water and sand concentrations will be high. However, as the well continues to produce, the oil content will increase, with concomitant diminuation of solids and water weights. To offset this advantage, the temperature of the produced stream decreases as the cycle progresses, with resultant increase in viscosity thereof.
A typical production stream would comprise about 20% water content and 5% solids content. However, in order to be acceptable to meet pipeline specifications, the basic sediments plus water content (BS & W) must not exceed 0.5% (by volume).
Additionally, the produced oil stream could well be at a temperature of 50.degree. to 100.degree. C. and display a viscosity of 5,000 cps. In order to meet current pipe line requirements it is stipulated that the viscosity of the stream be 250 cps at 20.degree. C.
Hence, it is necessary to clean the produced crude oil stream by removing water and solids therefrom and, by some means, to obtain a reduction in the viscosity of the heavy oil, so as to render it transportable in a pipe line.
It is conventional practice to subject the production stream initially to a free water knock-out step, by retaining the stream in a holding vessel where a large portion of the water content separates out under gravity. After this step, the water concentration of the production stream is typically 10%. However, this residual water is in a non-readily disengageable emulsified state. Therefore it is necessary to subject the stream to a more rigorous treatment. This is done by passing the oil/water emulsion stream to a phase separation vessel, termed a coalescing treater. In the treater, the oil is heated and admixed with emulsion-breaking chemicals, if necessary, to separate the water phase and solids from the lighter oil phase. Typically, once treated, the relatively pure oil exhibits a BS & W content below 0.5% by weight.
The treater vessel per se typically comprises a horizontal cylindrical vessel forming a sump portion at its lower end. In smaller units the treater vessel may be vertically disposed. Heating means, usually fire tubes, are provided to heat the vessel contents to the requisite temperature.
Operating conditions of the treater commonly comprise a pressure of up to 100 psig and temperature range of 50.degree. to 65.degree. C. The low temperature is maintained to ensure that the loss of light liquid hydrocarbons entrained in the vented gas product is minimized. Additionally, equipment problems arise when one attempts to operate fire tubes at higher temperatures.
After processing in a conventional treater, the pure heavy `treated` oil typically exhibits a viscosity in the range 5,000-25,000 cps at 20.degree. C.--although the actual viscosity of the oil, because of its elevated temperature, is somewhat lower.
As the viscosity of the treated oil fails to meet pipe line specifications, it has been the practice of oilfield operators to lower the viscosity thereof by addition thereto of a light hydrocarbon diluent. Typically, the diluent comprises condensates from a natural gas well or gas recovery plant. The dilution ratio required varies from one heavy oil reservoir to another, however it can be of the order of 20-40% by volume. A small portion of the diluent may be added upstream of the treater.
The principal disadvantage of this practice resides in the high costs of purchasing the diluent and transporting it to the well site and subsequently pumping it to the refinery site. Additionally, it is acknowledged that supplies of condensate are decreasing, whereas demand therefor remains high.
Before arriving at the present invention, applicant's original concept was to generate diluent at the well head and inject components of the formed diluent as a high temperature gaseous solvent into the reservoir, thereby mobilizing the oil contained therein. However, a study suggested that such a process would not be economically viable at this time and the concept was modified.
Applicants then considered the possibility of providing an on-site heavy oil partial up-grading process wherein either the viscosity of the oil would be reduced in the up-grading process or a diluent would be generated from the production stream. This would reduce or eliminate the necessity of purchasing the diluent and transporting it to the well site.
Consideration was given to existing processes for up-grading heavy oil. Prior art processes for upgrading heavy oil may be broadly classified as either refining with carbon elimination as a solid or refining without carbon rejection. The first class includes coking and heavy solvent de-asphalting processes. The second class encompasses thermal processes, exemplary of which are visbreaking, hydrovisbreaking and catalytic processes.
Delayed coking is a well known process in the art. It is directed toward the production of distillates by rejection of excess carbon in the form of coke. Traditionally, delayed coking takes place at pressures of about 10-20 psig and temperatures in the range of 800.degree.-850.degree. F. (425.degree. to 450.degree. C.).
Visbreaking involves the partial thermal decomposition of long hydrocarbon molecular chains by cleavage thereof into shorter chains. The extent, or severity, of a visbreaking process is parametric, depending upon reaction (or retention) time, temperature and pressure. Conventional visbreaking operates at a pressure in the range of 50-200 psig at temperatures ranging from 780.degree.-840.degree. F. (415.degree. to 450.degree. C.). Typical retention times range from a few minutes to 2 hours. Conventional visbreaking is normally associated with refineries and consists of passing a heavy oil or the bottoms from a topping still through a single pass coil in a direct fired heater. The heater effluent can go to a fractionation column or be blended with other lighter feed streams. A thermal quenching occurs which prevents the reaction from proceeding to the point of producing unwanted coke. Preheating and partial recycle may also be employed to improve efficiency and control.
With this background in mind, we have sought to devise a process which would provide the extent of cleaning and viscosity reduction needed to approach or meet pipe line specifications for oil over approximately 12 API and reduce the diluent requirements for oil below 12 API, which process would be characterized by:
minimal coke production; PA1 mild conditions, so that high pressure equipment would not be needed; PA1 flexibility, to cope with feeds having varying compositions, flow rates and pumping requirements; PA1 adaptability for use on a small scale at a well or battery site in the oilfield or pipeline receiving station; and PA1 simplicity of operation.